Edgar Filing: GOODRICH PETROLEUM CORP

Form 10-Q for Period Ended March 31, 2006

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

þ	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended March 31, 2006

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 001-7940

GOODRICH PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Delaware

76-0466193

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

808 Travis, Suite 1320

Houston, Texas

77002

(Address of principal executive offices)

(Zip Code)

(Registrant’s telephone number, including area code): (713) 780-9494

Securities Registered Pursuant to Section 12 (b) of the Act:


Title of each class		Name of exchange on which registered
Common Stock, par value $0.20 per share		New York Stock Exchange

Securities Registered Pursuant to Section 12 (g) of the Act:

None

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ¨ Accelerated filer þ Non-accelerated filer ¨

Indicate by check mark whether the Registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes ¨ No þ

The number of shares outstanding of the Registrant’s common stock as of May 5, 2006 was 24,932,898.

GOODRICH PETROLEUM CORPORATION

TABLE OF CONTENTS


		Page
PART I	FINANCIAL INFORMATION	3

ITEM 1.	FINANCIAL STATEMENTS

	Consolidated Balance Sheets: March 31, 2006 and December 31, 2005	3

	Consolidated Statements of Operations: For the three months ended March 31, 2006 and 2005	4

	Consolidated Statements of Cash Flows: For the three months ended March 31, 2006 and 2005	5

	Consolidated Statements of Comprehensive Income (Loss): For the three months ended March 31, 2006 and 2005	6

	Notes to the Consolidated Financial Statements	7

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	16

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	23

ITEM 4.	CONTROLS AND PROCEDURES	23

PART II	OTHER INFORMATION	24

ITEM 1A.	RISK FACTORS	24

ITEM 6.	EXHIBITS	24

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Amounts)


	March 31, 2006			December 31, 2005
	(unaudited)
Assets
Current assets:
Cash and cash equivalents	$	1,503		$	19,842
Accounts receivable, trade and other, net of allowance		9,998			6,397
Accrued oil and gas revenue		9,937			11,863
Fair value of interest rate derivatives		496			107
Prepaid expenses and other		456			463

Total current assets		22,390			38,672

Property and equipment:
Oil and gas properties (successful efforts method)		379,933			316,286
Furniture, fixtures and equipment		1,207			1,075

		381,140			317,361
Less: Accumulated depletion, depreciation and amortization		(85,950	)		(74,229	)

Net property and equipment		295,190			243,132

Other assets:
Restricted cash		2,039			2,039
Deferred tax asset		5,698			11,580
Other		1,062			1,103

Total other assets		8,799			14,722

Total assets	$	326,379		$	296,526

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	40,098		$	31,574
Accrued liabilities		21,449			15,973
Fair value of oil and gas derivatives		11,444			23,271
Accrued abandonment costs		92			92

Total current liabilities		73,083			70,910
Long-term debt		30,000			30,000
Accrued abandonment costs		8,321			7,868
Fair value of oil and gas derivatives		3,283			6,159

Total liabilities		114,687			114,937

Stockholders’ equity:
Preferred stock: 10,000,000 shares authorized:
Series A convertible preferred stock, $1.00 par value, 791,968 shares issued and outstanding at December 31, 2005		—			792
Series B convertible preferred stock, $1.00 par value, 2,250,000 and 1,650,000 shares issued and outstanding		2,250			1,650
Common stock: $0.20 par value, 50,000,000 shares authorized; issued and outstanding 24,922,147 and 24,804,737 shares, respectively		4,984			4,961
Additional paid in capital		208,265			187,967
Accumulated deficit		(74	)		(8,649	)
Unamortized restricted stock awards		–			(2,066	)
Accumulated other comprehensive loss		(3,733	)		(3,066	)

Total stockholders’ equity		211,692			181,589

Total liabilities and stockholders’ equity	$	326,379		$	296,526

See notes to consolidated financial statements

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

(Unaudited)


	Three Months Ended March 31,
	2006			2005
Revenues:
Oil and gas revenues	$	24,905		$	12,431
Other		346			129

		25,251			12,560

Operating expenses:
Lease operating expense		3,584			2,244
Production taxes		1,584			786
Depreciation, depletion and amortization		9,832			5,846
Exploration		1,494			1,524
General and administrative		3,771			1,620
Gain on sale of assets		—			(151	)

		20,265			11,869

Operating income		4,986			691

Other income (expense):
Interest expense		(695	)		(307	)
Gain (loss) on derivatives not qualifying for hedge accounting		13,542			(9,843	)

		12,847			(10,150	)

Income (loss) before income taxes		17,833			(9,459	)
Income tax (expense) benefit		(6,241	)		3,308

Net income (loss)		11,592			(6,151	)
Preferred stock dividends		1,481			158
Preferred stock redemption premium		1,536			—

Net income (loss) applicable to common stock	$	8,575		$	(6,309	)

Net income (loss) applicable to common stock per common share:
Basic	$	0.34		$	(0.30	)

Diluted	$	0.34		$	(0.30	)

Average common shares outstanding:
Basic		24,860			20,784

Diluted		25,366			20,784

See notes to consolidated financial statements

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)


	Three Months Ended March 31,
	2006			2005
Cash flows from operating activities:
Net income (loss)	$	11,592		$	(6,151	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities -
Depletion, depreciation and amortization		9,832			5,846
Unrealized (gain) loss on derivatives not qualifying for hedge accounting		(16,121	)		10,423
Deferred income taxes		6,241			(3,308	)
Dry hole costs		—			641
Amortization of leasehold costs		1,158			542
Stock based compensation		932			240
Gain on sale of assets		—			(151	)
Other non cash items		60			63
Changes in assets and liabilities -
Accounts receivable and other assets		(1,668	)		322
Accounts payable and accrued liabilities		13,747			1,713

Net cash provided by operating activities		25,773			10,180

Cash flows from investing activities:
Additions to oil and gas properties		(63,372	)		(20,860	)
Additions to furniture and fixtures		(132	)		(34	)
Proceeds from sale of assets		909			137

Net cash used in investing activities		(62,595	)		(20,757	)

Cash flows from financing activities:
Net proceeds from Series B Preferred Stock offering		29,037			—
Redemption of Series A Preferred Stock		(9,310	)		—
Principal payments of bank borrowings		—			(5,500	)
Proceeds from bank borrowings		—			14,000
Deferred financing costs		—			(133	)
Exercise of stock options and warrants		—			458
Preferred stock dividends		(1,229	)		(158	)
Production payments		—			(124	)
Other		(15	)		(33	)

Net cash provided by financing activities		18,483			8,510

Decrease in cash and cash equivalents		(18,339	)		(2,067	)
Cash and cash equivalents, beginning of period		19,842			3,449

Cash and cash equivalents, end of period	$	1,503		$	1,382

Supplemental disclosures of cash flow information:
Cash paid during the period for interest	$	674		$	159

Cash paid during the period for income taxes	$	—		$	15

See notes to consolidated financial statements

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In Thousands)

(Unaudited)


	Three Months Ended March 31,
	2006			2005
Net income (loss)	$	11,592		$	(6,151	)

Other comprehensive loss:
Change in fair value of derivatives (1)		(1,079	)		(3,166	)
Reclassification adjustment (2)		412			1,421

Other comprehensive loss		(667	)		(1,745	)

Comprehensive income (loss)	$	10,925		$	(7,896	)


(1) Net of income tax benefit of:	$	581	$	1,074
(2) Net of income tax expense of:	$	222	$	764

See notes to consolidated financial statements

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE A—Basis of Presentation

The consolidated financial statements of Goodrich Petroleum Corporation (“Goodrich” or “the Company” or “we”) included in this Form 10-Q have been prepared, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) and, accordingly, certain information normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States has been condensed or omitted. The consolidated financial statements reflect all normal recurring adjustments that, in the opinion of management, are necessary for a fair presentation. Significant intercompany balances and transactions have been eliminated in consolidation. Certain reclassifications have been made to the prior year statements to conform to the current year presentation.

The accompanying consolidated financial statements of the Company should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2005. The results of operations for the three months ended March 31, 2006 are not necessarily indicative of the results to be expected for the full year.

NOTE B—Recent Accounting Pronouncements

In March 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard (“SFAS”) No.156, “Accounting for Servicing of Financial Assets” (“SFAS 156”), which requires all separately recognized servicing assets and servicing liabilities be initially measured at fair value. SFAS 156 permits, but does not require, the subsequent measurement of servicing assets and servicing liabilities at fair value. Adoption is required as of the beginning of the first fiscal year that begins after September 15, 2006. Early adoption is permitted. The adoption of SFAS 156 is not expected to have a material effect on our consolidated financial position, results of operations or cash flows.

In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments, an amendment of FASB Statements No. 133 and 140” (“SFAS 155”). SFAS 155 clarifies certain issues relating to embedded derivatives and beneficial interests in securitized financial assets. The provisions of SFAS 155 are effective for all financial instruments acquired or issued after fiscal years beginning after September 15, 2006. We are currently assessing the impact that the adoption of SFAS 155 will have on our consolidated financial position, results of operations or cash flows.

In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”), replacing SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”), and superceding Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”). SFAS 123R requires recognition of share-based compensation in the financial statements. SFAS 123R is effective as of the first annual reporting period that begins after June 15, 2005 and was adopted on January 1, 2006. See Note C for further details.

NOTE C—Stock-Based Compensation

Share-Based Employee Compensation Plans

On February 1, 2006, our Board of Directors approved our 2006 Long-Term Incentive Plan (the “2006 Plan”), subject to stockholder approval at our annual meeting of stockholders in May 2006. The 2006 Plan is similar to and will, upon shareholder approval, replace our previously adopted 1995 Incentive Plan (the “1995 Plan”) and 1997 Non-Employee Directors’ Stock Option Plan (the “Directors’ Plan”). No further awards will be granted under the previously adopted plans, however, those plans shall continue to apply to and govern awards made thereunder. Under the 2006 Plan, a maximum of 2.0 million new shares are reserved for issuance as

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

awards of share options to officers, employees and non-employee directors. Share options granted to officers and employees will generally become exercisable in 33% increments over a three year period and to the extent not exercised, expire on the tenth anniversary of the date of grant. Share options granted to non-employee directors will usually be immediately exercisable and to the extent not exercised, expire on the tenth anniversary of the date of grant. The exercise price of share options granted under the 2006 Plan will equal the market value of the underlying stock on the date of grant. The 1995 Plan expired according to its original terms on August 16, 2005. However, on February 1, 2006, our Board of Directors approved the extension of the 1995 Plan through December 31, 2005 and the granting of a total of 101,129 shares of restricted stock and 525,000 stock options to certain of our employees and directors as of December 6, 2005, subject to approval at our 2006 annual meeting of stockholders in May 2006. For accounting purposes, such restricted shares and options have been valued as of February 9, 2006, the date on which our directors and executive officers reached a level of more than 50% ownership of our common stock, so that shareholder approval of those actions was no longer uncertain.

Share options previously granted under the 1995 Plan become exercisable in 33% increments over a three year period and to the extent not exercised, expire on the tenth anniversary of the date of grant. Share options previously granted under the Directors’ Plan generally become exercisable immediately and expire, if not exercised, ten years thereafter. The exercise price of share options granted under the 1995 Plan and the Directors’ Plan equals the market value of the underlying stock on the date of grant. At March 31, 2006, options to purchase 1,044,500 shares of our common stock were outstanding under the 1995 Plan and the Directors’ Plan.

Adoption of New Accounting Pronouncement

Stock based compensation for the three months ended March 31, 2006 of $0.9 million has been recognized as a component of general and administrative expenses in the accompanying Consolidated Financial Statements.

Effective January 1, 2006 we adopted SFAS 123R, which requires us to measure the cost of employee services received in exchange for all equity awards granted, including stock options and restricted stock, based on the fair market value of the award as of the grant date, net of estimated forfeitures. SFAS 123R supersedes SFAS 123 and APB 25. We have adopted SFAS 123R using the modified prospective application method of adoption, which requires us to record compensation cost related to unvested stock awards as of December 31, 2005 by recognizing the unamortized grant date fair value of these awards over the remaining service periods of those awards with no change in historical reported earnings. Awards granted after December 31, 2005 are valued at fair value in accordance with provisions of SFAS 123R and recognized on a straight line basis over the service periods of each award. We estimated forfeiture rates for the first quarter of 2006 based on our historical experience.

Prior to 2006, we accounted for stock-based compensation in accordance with APB 25 using the intrinsic value method, which did not require that compensation cost be recognized for our stock options provided the option exercise price was established at 100% of the common stock fair market value on the date of grant. Under APB 25, we were required to record expense over the vesting period for the value of restricted stock granted. Prior to 2006, we provided pro forma disclosure amounts in accordance with SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure” (SFAS 148), as if the fair value method defined by SFAS 123 had been applied to our stock-based compensation. Our net loss and net loss per share for the three months ended March 31, 2005 would have been greater if compensation cost related to stock options had been recorded in the financial statements based on fair value at the grant dates.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The estimated fair value of the options granted during 2006 and prior years was calculated using a Black Scholes Merton option pricing model (Black Scholes). The following summarizes the assumptions used in the 2006 Black Scholes model:


Risk free interest rate	4.50	%
Weighted average volatility	54-57	%
Dividend yield	0	%
Expected years until exercise	5-6

The Black Scholes model incorporates assumptions to value stock-based awards. The risk-free rate of interest for periods within the expected term of the option is based on a zero-coupon U.S. government instrument over the expected term of the equity instrument. Expected volatility is based on the historical volatility of our common stock. We generally use the midpoint of the vesting period and the life of the grant to estimate employee option exercise timing (expected term) within the valuation model. This methodology is not materially different from our historical data on exercise timing. In the case of director options, we used historical exercise behavior. Employees and directors that have different historical exercise behavior with regard to option exercise timing and forfeiture rates are considered separately for valuation and attribution purposes.

Pro forma net loss as if the fair value based method had been applied to all awards is as follows (in thousands, except per share amounts):


	Three Months Ended March 31, 2005
Net loss as reported	$	(6,151	)
Add: Stock based compensation programs recorded as expense, net of tax		158
Deduct: Total stock based compensation expense, net of tax		(265	)

Pro forma net loss	$	(6,258	)

Net loss applicable to common stock as reported	$	(6,309	)
Add: Stock based compensation programs recorded as expense, net of tax		158
Deduct: Total stock based compensation expense, net of tax		(265	)

Pro forma net loss	$	(6,416	)

Net loss applicable to common stock per share:
Basic and diluted – as reported	$	(0.30	)
Basic and diluted – pro forma	$	(0.30	)

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the components of our stock-based compensation programs recorded as expense (in thousands):


	Three Months Ended, March 31,
	2006			2005
Restricted stock:
Pretax compensation expense	$	426		$	240
Tax benefit		(149	)		(82	)

Restricted stock expense, net of tax	$	277		$	158

Stock options:
Pretax compensation expense	$	506		$	—
Tax benefit		(177	)		—

Stock option expense, net of tax	$	329		$	—

Total share based compensation:
Pretax compensation expense	$	932		$	240
Tax benefit		(326	)		(82	)

Total share based compensation expense, net of tax	$	606		$	158

As of March 31, 2006, $4.1 million and $8.1 million of total unrecognized compensation cost related to restricted stock and stock options, respectively, is expected to be recognized over a weighted average period of approximately 2.0 years for restricted stock and 2.4 years for stock options.

Option activity under our stock option plans as of March 31, 2006 and changes during the three months ended March 31, 2006 were as follows:


	Shares	Weighted Average Exercise Price		Weighted Average Remaining Contractual Term In Years	Aggregate Intrinsic Value
Outstanding at January 1, 2006	519,500	$	13.70
Granted	525,000		23.39

Outstanding at March 31, 2006	1,044,500	$	18.57	8.7	$	8,805,368

Exercisable at March 31, 2006	372,833	$	12.61	7.4	$	5,364,251

The aggregate intrinsic value in the table above represents the total pre-tax intrinsic value (the difference between our closing stock price on the last trading day of the first quarter of 2006 and the exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on March 31, 2006. The amount of aggregate intrinsic value will change based on the fair market value of our stock.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes information on unvested restricted stock outstanding as of March 31, 2006:


	Number of Shares		Weighted Average Grant-Date Fair Value
Unvested at start of quarter	263,890		$	11.13
Vested	(110,935	)		7.60
Granted	101,629			23.42

Unvested at end of quarter	254,584		$	17.57

NOTE D—Asset Retirement Obligations

SFAS 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets and requires that an asset retirement cost should be capitalized as part of the cost of the related long- lived asset and subsequently allocated to expense using a systematic and rational method. We adopted SFAS 143 on January 1, 2003 and recorded an incremental liability for asset retirement obligations of $1.4 million, additional oil and gas properties, net of accumulated depletion, depreciation and amortization, in the amount of $1.1 million and a net of tax cumulative effect of change in accounting principle of $0.2 million. The reconciliation of the beginning and ending asset retirement obligation for the period ending March 31, 2006 is as follows (in thousands):


Beginning balance	$	7,960
Liabilities incurred		359
Liabilities settled		—
Accretion expense (reflected in depletion, depreciation and amortization expense)		94

Ending balance		8,413
Less current portion		(92	)

	$	8,321

NOTE E—Long-Term Debt

Long-term debt consisted of the following balances (in thousands):


	March 31, 2006		December 31, 2005
Second lien term loan	$	30,000	$	30,000
Less current maturities		—		—

Total long-term debt	$	30,000	$	30,000

On November 17, 2005, we amended our existing credit agreement and entered into an amended and restated senior credit agreement (the “Amended and Restated Credit Agreement”) and a funded $30.0 million second lien term loan (the “Second Lien Term Loan Agreement”) that expanded our borrowing capabilities and extended our credit facility for an additional two years. Total lender commitments under the Amended and Restated Credit Agreement were increased from $50.0 million to $200.0 million and the maturity was extended from February 25, 2008 to February 25, 2010. Revolving borrowings under the Amended and Restated Credit Agreement are subject to periodic redeterminations of the borrowing base which is currently established at $75.0 million, and is currently scheduled to be redetermined in May 2006, based upon our 2005 year-end reserve report. With a portion of the net proceeds of the offering of our 5.375% Series B Cumulative Convertible Preferred Stock (the “Series B Convertible Preferred Stock”) in December 2005, we fully repaid all outstanding indebtedness on our revolver in the amount of $47.5 million leaving a zero balance outstanding as of December 31, 2005 (see Note F). Interest on revolving borrowings under the Amended and Restated Credit Agreement accrues at a rate calculated, at

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

our option, at either the bank base rate plus 0.00% to 0.50%, or LIBOR plus 1.25% to 2.00%, depending on borrowing base utilization. BNP Paribas (“BNP”) is the lead lender and administrative agent under the amended credit facility with Comerica Bank and Harris Nesbit Financing, Inc. as co-lenders.

The terms of the Amended and Restated Credit Agreement require us to maintain certain covenants. Capitalized terms are defined in the credit agreement. The covenants include:

•

Current Ratio of 1.0/1.0;

•

Interest Coverage Ratio which is not less than 3.0/1.0 for the trailing four quarters, and

•

Tangible Net Worth of not less than $53,392,838, plus 50% of cumulative net income after September 30, 2004, plus 100% of the net proceeds of any subsequent equity issuance.

As of March 31, 2006, we were in compliance with all of the financial covenants of the Amended and Restated Credit Agreement.

The Second Lien Term Loan Agreement provides for a 5-year, non-revolving loan of $30.0 million which was funded on November 17, 2005 and is due in a single maturity on November 17, 2010. Optional prepayments of term loan principal can be made in amounts of not less than $5.0 million during the first year at a 1% premium and without premium after the first year. Interest on term loan borrowings accrues at a rate calculated, at our option, at either base rate plus 3.50%, or LIBOR plus 4.50%, and is payable quarterly. BNP is the lead lender and administrative agent under the Second Lien Term Loan Agreement.

The terms of the Second Lien Term Loan Agreement require us to maintain certain covenants. Capitalized terms are defined in the loan agreement. The covenants include:

•

Total Debt to EBITDAX Ratio which is not greater than 4.0/1.0 for the most recent period of four fiscal quarters for which financial statements are available and

•

Asset Coverage Ratio to be not less than 1.5/1.0.

As of March 31, 2006, we were in compliance with all of the financial covenants of the Second Lien Term Loan Agreement.

NOTE F—Preferred Stock

In December 2005, 1,650,000 shares of our Series B Convertible Preferred Stock were issued in a private placement for net proceeds of $79.8 million (after offering costs of $2.7 million). On January 23, 2006, the initial purchasers exercised their option to purchase an additional 600,000 shares of Series B Convertible Preferred Stock at the same price per share, resulting in net proceeds of $29.0 million.

As part of this transaction we filed a registration statement with the SEC on April 20, 2006 for the purpose of registering the resale of the shares of common stock issuable pursuant to the purchase agreement. As of the date we filed this Form 10-Q, the registration statement had not been declared effective by the SEC.

During the first quarter of 2006 we completed the redemption of our Series A Convertible Preferred Stock. Of the previously outstanding shares of Series A Convertible Preferred Stock, holders of 15,539 shares elected to convert such shares into a net total of 6,466 shares of our common stock and the remaining shares were redeemed in cash for $12 per share, plus accrued dividends. The total redemption cost to us was approximately $9.3 million and was funded from available cash resources. This amount includes a $1.5 million redemption premium which is treated in the same manner as preferred stock dividends on the Consolidated Statement of Operations.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE G—Net Income (Loss) Per Share

Net income (loss) applicable to common stock was used as the numerator in computing basic and diluted income (loss) per common share for the three months ended March 31, 2006 and 2005. The following table reconciles the weighted average shares outstanding used for these computations (in thousands):


	For the Three Months Ended March 31,
	2006	2005
Basic Method	24,860	20,784
Dilutive Stock Warrants	194	—
Dilutive Stock Options and Restricted Stock	312	—

Dilutive Method	25,366	20,784

NOTE H—Hedging Activities

Commodity Hedging Activity

We enter into swap contracts, costless collars or other hedging agreements from time to time to manage the commodity price risk for a portion of our production. We consider these to be hedging activities and, as such, monthly settlements on these contracts are reflected in our crude oil and natural gas sales, provided the contracts are deemed to be “effective” hedges under FAS 133. Our strategy, which is administered by the Hedging Committee of the Board of Directors, and reviewed periodically by the entire Board of Directors, has been to generally hedge between 30% and 70% of our production. As of March 31, 2006, the commodity hedges we utilized were in the form of: (a) swaps, where we receive a fixed price and pay a floating price, based on NYMEX quoted prices; and (b) collars, where we receive the excess, if any, of the floor price over the reference price, based on NYMEX quoted prices, and pay the excess, if any, of the reference price over the ceiling price. Hedge ineffectiveness results from difference changes in the NYMEX contract terms and the physical location, grade and quality of our oil and gas production.

As of March 31, 2006, our open forward position on our outstanding commodity hedging contracts was as follows:


Swaps	Volume	Average Price
Natural gas (MMBtu/day)
2Q 2006	15,000	$	6.95
3Q 2006	15,000		6.95
4Q 2006	15,000		6.95
1Q 2007	10,000		7.77

Oil (Bbl/day)
2Q 2006	800	$	50.80
3Q 2006	800		50.80
4Q 2006	800		50.80
2007	400		53.35

Table continued on following page

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Collars	Volume	Average Floor/Cap
Natural gas (MMBtu/day)
1Q 2007	25,000	$	7.00 – $14.92
2Q 2007	30,000		7.00 – 14.75
3Q 2007	30,000		7.00 – 14.75
4Q 2007	30,000		7.00 – 14.75

Oil (Bbl/day)
2007	400	$	60.00 – $76.50

The fair value of the oil and gas hedging contracts in place at March 31, 2006 resulted in a net liability of $14.7 million. As of March 31, 2006, $2.8 million (net of $1.5 million in income taxes) of deferred losses on derivative instruments accumulated in other comprehensive loss are expected to be reclassified into earnings during the next twelve months. For the three months ended March 31, 2006, we recognized in earnings a gain on derivatives not qualifying for hedge accounting in the amount of $13.5 million (also included in this amount are settlement payments on ineffective gas hedges). This gain was recognized because our gas swaps have been deemed ineffective since the fourth quarter of 2004, and accordingly, the changes in fair value of such hedges could no longer be reflected in other comprehensive loss. In addition, three collars did not qualify for hedge accounting treatment and those changes in fair value have been recognized in earnings. For the three months ended March 31, 2006, $0.5 million of previously deferred losses (net of $0.2 million in income taxes) was reclassified from accumulated other comprehensive loss to oil and gas sales as the cash flow of the hedged items was recognized.

Despite the measures taken by us to attempt to control price risk, we remain subject to price fluctuations for natural gas and crude oil sold in the spot market. Prices received for natural gas sold on the spot market are volatile due primarily to seasonality of demand and other factors beyond our control. Domestic crude oil and gas prices could have a material adverse effect on our financial position, results of operations and quantities of reserves recoverable on an economic basis.

Interest Rate Swaps

We have a variable-rate debt obligation that exposes us to the effects of changes in interest rates. To partially reduce our exposure to interest rate risk, from time to time we enter into interest rate swap agreements. At March 31, 2006 we had the following interest rate swaps in place with BNP (in millions):


Effective Date	Maturity Date	LIBOR Swap Rate		Notional Amount
02/27/06	02/26/07	4.08	%	$	23.0
02/27/06	02/26/07	4.85	%		17.0
02/26/07	02/26/09	4.86	%		40.0

The fair value of the interest rate swap contracts in place at March 31, 2006, resulted in an asset of $0.5 million. As of March 31, 2006, $153,000 (net of $83,000 in income taxes) of deferred net gains on derivative instruments accumulated in other comprehensive income are expected to be reclassified into earnings during the next twelve months. During the quarter ended March 31, 2006, $28,000 of previously deferred gains (net of $14,500 in income taxes) were reclassified from accumulated other comprehensive income to interest expense as the cash flow of the hedged items was recognized.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We entered into two interest rate swaps to protect against movements in interest rates during the fourth quarter of 2005. The documentation was not prepared at the time of inception for these hedges and as a result, we were not entitled to apply hedge accounting to these instruments. The failure to qualify for hedge accounting requires that all changes in the fair value of the interest rate swap be recorded in the consolidated statements of operations. Accordingly, for the three months ended March 31, 2006, we recognized in earnings a gain of approximately $0.2 million, which is included in the aforementioned total gain of $13.5 million.

NOTE I—Commitments and Contingencies

In July 2005, we received a Notice of Proposed Tax Due from the State of Louisiana asserting that we underpaid our Louisiana franchise taxes for the years 1998 through 2004 in the amount of $0.5 million. The Notice of Proposed Tax Due includes additional assessments of penalties and interest in the amount of $0.4 million for a total asserted liability of $0.9 million. We believe that we have fully paid our Louisiana franchise taxes for the years in question; therefore, we intend to vigorously contest the Notice of Proposed Tax Due. We have commenced our analysis of this contingency and have not recorded any provision for possible payment of additional Louisiana franchise taxes nor any related penalties and interest.

We are party to additional lawsuits arising in the normal course of business. We intend to defend these actions vigorously and believe, based on currently available information, that adverse results or judgments from such actions, if any, will not be material to our financial position or results of operations.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Disclosure Regarding Forward Looking Statement

Certain statements in this Quarterly Report on Form 10-Q regarding future expectations and plans for future activities may be regarded as “forward looking statements” within the meaning of Private Securities Litigation Reform Act of 1995. They are subject to various risks, such as financial market conditions, operating hazards, drilling risks and the inherent uncertainties in interpreting engineering data relating to underground accumulations of oil and gas, as well as other risks discussed in detail in our Annual Report on Form 10-K, and such changes to these factors which are discussed in Part II, Item 1A of this Form 10-Q. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct.

Executive Overview

General

We are an independent oil and gas company engaged in the exploration, exploitation, development and production of oil and natural gas properties primarily in the Cotton Valley Trend of East Texas and Northwest Louisiana and in the transition zone of South Louisiana.

Our business strategy is to provide long term growth in net asset value per share, through the growth and expansion of our oil and gas reserves and production. We focus on adding reserve value through the development of our relatively low risk development drilling program in the Cotton Valley Trend, while maintaining our drilling activities in select high impact well locations in South Louisiana. We continue to aggressively pursue the acquisition and evaluation of prospective acreage, oil and gas drilling opportunities and potential property acquisitions.

Source of Revenue

We derive our revenues from the sale of oil and natural gas that is produced from our properties. Revenues are a function of both the volume produced and the prevailing market price at the time of sale. Production volumes, while somewhat predictable after wells have begun producing, can be impacted for various reasons. Hurricanes Katrina and Rita in the third quarter of 2005 are an example of how production volumes can be impacted to defer volumes from the current period to future periods. The price of oil and natural gas is a primary factor affecting our revenues. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we utilize derivative instruments to hedge future sales prices on a portion of our oil and natural gas production. While the derivative instruments may protect downward price fluctuation, the use of certain types of derivative instruments may prevent us from realizing the full benefit of upward price movements.

First Quarter 2006 Highlights

Our development, financial and operating performance for the first quarter 2006 included the following highlights:

•

We increased our oil and gas production volumes to approximately 36,500 Mcfe per day, representing an increase of 72% from the first quarter of 2005 and an increase of approximately 27%, on a sequential basis, from the fourth quarter of 2005.

•

We completed drilling operations on 30 gross wells in the first quarter of 2006.

•

Following our initial issuance of 1,650,000 shares of our 5.375% Series B Cumulative Convertible Preferred Stock (the “Series B Convertible Preferred Stock”) in December 2005, we issued an additional 600,000 shares of Series B Convertible Preferred Stock in January 2006 upon the full exercise by the initial purchasers of their option to purchase additional shares generating net proceeds of $29.0 million.

•

We funded our capital expenditures of $63.4 million in the first quarter of 2006 through a combination of cash flow from operations, net proceeds from the aforementioned Series B Convertible Preferred Stock transaction and available cash.

•

We redeemed our Series A Convertible Preferred Stock at the net cost of $9.3 million, including a redemption premium of $1.5 million, which reduced net income applicable to common stock by $0.06 per basic share.

•

Our after-tax net income reflected an income tax provision rate of 35% in the first quarter of 2006; however, we did not incur any income taxes on a current basis due to our substantial tax net operating loss carrryforwards and other factors.

A more complete overview and discussion of our operations can be found in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2005 Form 10-K, as amended.

Hurricanes Katrina and Rita Update

In August and September 2005, Hurricanes Katrina and Rita caused damage to our assets on the Gulf Coast. The most significant damage was concentrated on one producing well (Norton) and offshore facilities in our Burrwood/West Delta 83 field. As of March 31, 2006, we have incurred costs associated with Hurricane Katrina of approximately $2.3 million in this field, which are net of our share of insurance proceeds received and accrued to date, and our partners’ share of costs incurred to date. We anticipate that we will be fully reimbursed for all of our insured losses, after deductibles are met. We have an approximate 63% working interest in the Burrwood/West Delta field and the remaining 37% working interest owners participate in the costs, insurance deductible and insurance proceeds that are ultimately received. We anticipate that additional costs related to Hurricane Katrina are still to be incurred, although we do not believe the amount to be significant.

Repairs caused by Hurricane Rita related to our Second Bayou field are substantially complete and we incurred net damage costs of approximately $0.2 million. We have recorded a loss of $0.2 million to date representing amounts incurred that will not ultimately be covered by insurance, of which an additional $20,000 was recorded in the first quarter of 2006. We have an approximate 26% working interest in the Second Bayou field and the remaining 74% working interest owners participate in the costs, insurance deductible and insurance proceeds that are ultimately received.

As claims are submitted to the insurance companies, they are reviewed and preliminary payments made until all losses are incurred and documented. A final payment will be made once we and our insurers agree on the total measurement value of the claim, which is expected sometime during the second quarter of 2006.

Three Months Ended March 31, 2006 Compared to Three Months Ended March 31, 2005

For the three months ended March 31, 2006, we reported net income applicable to common stock of $8.6 million, or $0.34 per basic share on total revenue of $25.3 million as compared with a net loss applicable to common stock of $6.3 million, or $0.30 per basic share, on total revenue of $12.6 million for the three months ended March 31, 2005.

Oil and Natural Gas Revenues

Revenues presented in the table and the discussion below represent revenue from sales of our oil and natural gas production volumes and include the realized gains and losses on the effective portion of our derivative instruments as further described under Note H to the Consolidated Financial Statements.


	Three Months Ended March 31,						% Change from 2005 to 2006
	2006			2005			% Change from 2005 to 2006
Production:
Natural gas (MMcf)		2,620			1,326		98	%
Oil and condensate (MBbls)		111			98		13	%
Total (MMcfe)		3,287			1,915		72	%
Revenues from production (in thousands):
Natural gas	$	18,664		$	8,620		117	%
Effects of cash flow hedges		—			—		—

Total	$	18,664		$	8,620		117	%

Oil and condensate	$	6,992		$	5,019		39	%
Effects of cash flow hedges		(751	)		(1,208	)	(38	%)

Total	$	6,241		$	3,811		64	%

Natural gas, oil and condensate	$	25,656		$	13,639		88	%
Effects of cash flow hedges		(751	)		(1,208	)	(38	%)

Total revenues from production	$	24,905		$	12,431		100	%

Average sales price per unit:
Natural gas (per Mcf)	$	7.13		$	6.50		10	%
Effects of cash flow hedges (per Mcf)		—			—		—

Total (per Mcf)	$	7.13		$	6.50		10	%

Oil and condensate (per Bbl)	$	62.84		$	51.16		23	%
Effects of cash flow hedges (per Bbl)		(6.75	)		(12.32	)	(45	%)

Total (per Bbl)	$	56.09		$	38.84		44	%

Natural gas, oil and condensate (per Mcfe)	$	7.81		$	7.12		10	%
Effects of cash flow hedges (per Mcfe)		(0.23	)		(0.63	)	(64	%)

Total (per Mcfe)	$	7.58		$	6.49		17	%

Excluding the effects of settled derivatives, revenues from production increased 88% in the first quarter of 2006 compared to the same period in 2005 due primarily to a substantial increase in Cotton Valley Trend production. Revenues were also impacted favorably by a 10% increase in our sales price per unit.

Lease Operating. Lease operating expense for the first quarter of 2006 increased on an absolute basis ($3.6 million compared to $2.2 million) but decreased on a per unit basis ($1.09 per Mcfe compared to $1.17 per Mcfe) from the first quarter of 2005. This decrease in unit costs was primarily attributable to a greater proportion of our production volumes coming from the lower cost environment in the Cotton Valley Trend. Our South Louisiana lease operating expenses were negatively impacted by an accrual of $350,000 for the estimated costs of cleaning up an oil spill that occurred from a non-producing well in our Plumb Bob field on March 21, 2006. The spill of an estimated 1,000 to 1,500 barrels of oil was quickly contained and the costs of site restoration will be covered by our insurance once a deductible is met. Our cost accrual for site restoration reflects our share of the insurance deductible.

Production Taxes. Production taxes increased to $1.6 million for the first quarter of 2006 compared to $0.8 million for the comparable period in 2005 due to an increase in production volumes and product prices. Our Cotton Valley Trend wells qualify for the “Tight Gas Sands” credit allowed for severance tax in the State of Texas. While we have only partially reflected such credits in the first quarter of 2006, we anticipate that we will incur a gradually lower production tax rate in the future as we add further Cotton Valley wells to our production base and as reduced rates are approved and credits are received.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) expense increased to $9.8 million from $5.8 million for the same period in 2005 primarily due to higher levels of production. The average DD&A rate decreased to $2.99 per Mcfe in the first quarter of 2006 compared to $3.05 per Mcfe in the same quarter of 2005 due to a higher percentage of production coming from fields with lower average DD&A rates.

General and Administrative. General and administrative expense increased to $3.8 million for the first quarter of 2006 compared to $1.6 million for the same period of 2005. This increase was primarily due to higher compensation related costs due to an approximate 40% increase in the number of employees at March 31, 2006 versus March 31, 2005. With the implementation of SFAS 123R, non cash stock based compensation expense increased approximately $0.7 million from the first quarter of 2005 due to expensing the fair value of stock options granted. See Note C for more information.

Interest Expense. Interest expense increased to $0.7 million from the first quarter 2005 amount of $0.3 million as a result of a higher average interest rate in the first quarter of 2006.

Gain (Loss) on Derivatives Not Qualifying for Hedge Accounting. Gain on derivatives not qualifying for hedge accounting was $13.5 million for the first quarter of 2006 compared to a loss of $9.8 million for the first quarter of 2005. The gain in 2006 includes an unrealized gain of $15.9 million for the changes in fair value of our ineffective oil and gas hedges, and a realized loss of $2.6 million for the effect of settled derivatives on our ineffective gas hedges. Our natural gas hedges were deemed ineffective, beginning in the fourth quarter of 2004, and we have been required to reflect the changes in the fair value of our natural gas hedges in earnings rather than in accumulated other comprehensive loss, a component of stockholders’ equity. Also included in the 2006 amount is an unrealized gain of $0.2 million related to interest rate swaps that did not qualify for hedge accounting treatment. To the extent that our hedges do not qualify for hedge accounting in the future, we will likewise be exposed to volatility in earnings resulting from changes in the fair value of our hedges.

Income taxes. Income taxes were an expense of $6.2 million for the first quarter of 2006 compared to a benefit of $3.3 million for the first quarter of 2005. The amounts in both periods essentially represented 35% of pre-tax income (loss). We did not however, incur any income taxes on a current basis due to our substantial tax net operating loss carrryforwards.

Liquidity and Capital Resources

Cash Flows

Operating activities. Net cash provided by operating activities increased to $25.8 million, up 153% from $10.2 million in the first quarter of 2005. The increase was a result of an increase in production levels and natural gas and crude oil prices and in the first quarter of 2006 compared to the first quarter of 2005, partially offset by increases in lease operating expenses and general and administrative expenses. Excluding the effect of settled derivatives, sales of oil and gas increased $12.0 million in the first quarter of 2006 compared to the same period in 2005, with realized oil and natural gas prices increasing 10% from the first quarter of 2005. Production volumes increased 72% in the first quarter of 2006 compared to the first quarter of 2005. Operating cash flow amounts are net of changes in our current assets and current liabilities, which resulted in adjustments to our operating cash flow in the amounts of $12.1 million and $2.0 million, respectively, in the three months ended March 31, 2006 and 2005, primarily reflecting increased revenue and expenditure activity associated with our Cotton Valley Trend wells.

Investing activities. Net cash used in investing activities was $62.6 million for the first quarter of 2006 compared to $20.8 million for the first quarter of 2005. For the three months ended March 31, 2006, capital expenditures totaled $63.4 million primarily due to accelerated development of our Cotton Valley Trend, which accounted for 94% of the capital costs incurred in the first quarter of 2006. We conducted drilling operations on approximately 30 gross wells, of which 28 were located in our Cotton Valley Trend, during the first quarter of 2006. We also received proceeds of $0.9 million from the sale of a salt water disposal facility.

Financing activities. Net cash provided by financing activities was $18.5 million for the first quarter of 2006 compared to $8.5 million for the first quarter of 2005. On January 23, 2006, the initial purchasers of the Series B Convertible Preferred Stock exercised their over-allotment option to purchase an additional 600,000 shares at the same price per share, resulting in net proceeds of $29.0 million, which will be used to fund our 2006 capital expenditure program. In February 2006, we fully redeemed all issued and outstanding shares of our Series A Convertible Preferred Stock at a cost of approximately $9.3 million. Dividends paid on both of our series of preferred stock totaled $1.2 million for the quarter.

In December 2005, our Board of Directors approved a preliminary 2006 capital expenditure budget of approximately $195.0 million, of which approximately 85% is expected to be focused on the relatively low risk development drilling program in the Cotton Valley Trend of East Texas and Northwest Louisiana and the remainder on our existing properties and new exploration programs. Our Board may increase our capital expenditure budget for 2006, subject to future economic conditions and financial resources. We expect to finance our 2006 capital expenditures through a combination of cash flow from operations and borrowings under our existing bank credit facility (see “Senior Credit Facility and Term Loan”). In the future, we may issue additional debt or equity securities to provide additional financial resources for our capital expenditures and other general corporate purposes. Our senior credit facility and term loan include certain financial covenants with which we were in compliance as of March 31, 2006. We do not anticipate a lack of borrowing capacity under our senior credit facility or term loan in the foreseeable future due to an inability to meet any such financial covenants nor a reduction in our borrowing base.

Senior Credit Facility and Term Loan

Restated Credit Agreement are subject to periodic redeterminations of the borrowing base which is currently established at $75.0 million, and is currently scheduled to be redetermined in May 2006, based upon our 2005 year-end reserve report. With a portion of the net proceeds of the offering of Series B Convertible Preferred Stock in December 2005, we fully repaid all outstanding indebtedness on our revolver in the amount of $47.5 million leaving a zero balance outstanding as of December 31, 2005 (see Note F). Interest on revolving borrowings under the Amended and Restated Credit Agreement accrues at a rate calculated, at our option, at either the bank base rate plus 0.00% to 0.50%, or LIBOR plus 1.25% to 2.00%, depending on borrowing base utilization. BNP Paribas (“BNP”) is the lead lender and administrative agent under the amended credit facility with Comerica Bank and Harris Nesbit Financing, Inc. as co-lenders.

The terms of the Amended and Restated Credit Agreement require us to maintain certain covenants. Capitalized terms are defined in the credit agreement. The covenants include:

•

Current Ratio of 1.0/1.0;

•

Interest Coverage Ratio which is not less than 3.0/1.0 for the trailing four quarters, and

•

Tangible Net Worth of not less than $53,392,838, plus 50% of cumulative net income after September 30, 2004, plus 100% of the net proceeds of any subsequent equity issuance.

As of March 31, 2006, we were in compliance with all of the financial covenants of the Amended and Restated Credit Agreement. In the second quarter of 2006, we resumed borrowings under the revolving credit facility in order to fund our 2006 capital expenditure program. Borrowings to date are $25.5 million.

The terms of the Second Lien Term Loan Agreement require us to maintain certain covenants. Capitalized terms are defined in the loan agreement. The covenants include:

•

Total Debt to EBITDAX Ratio which is not greater than 4.0/1.0 for the most recent period of four fiscal quarters for which financial statements are available and

•

Asset Coverage Ratio to be not less than 1.5/1.0.

As of March 31, 2006, we were in compliance with all of the financial covenants of the Second Lien Term Loan Agreement.

Cotton Valley Trend

Our relatively low risk development drilling program in the Cotton Valley Trend is primarily centered in and around Rusk, Panola, Angelina and Nacogdoches Counties, Texas, and DeSoto and Caddo Parishes, Louisiana. In addition, we have recently expanded our acreage position in the Trend to include Harrison, Smith and Upshur Counties of Texas. We have steadily increased our acreage position in these areas over the last two years to approximately 130,000 gross acres as of April 30, 2006. As of April 30, 2006, we have drilled and/or logged a cumulative total of 100 Cotton Valley wells with a 100% success rate, of which drilling operations were conducted on 28 gross wells during the first quarter of 2006. Our net production volumes from our Cotton Valley Trend wells aggregated approximately 22,200 Mcfe of gas per day in the first quarter of 2006, or approximately 61% of our total oil and gas production in the period.

South Louisiana Operations

Burrwood/West Delta 83 Fields — During the first quarter of 2006, we conducted drilling activities on our Norton II development prospect. Subsequent to the end of the quarter, we reached total depth and logged apparent oil and natural gas pay over an approximate 100 feet of gross (60 feet net) interval in the 10,500’ sand. We expect to initiate production from the well during the second quarter of 2006.

In late August 2005, our Burrwood/West Delta 83 field was shut-in due to Hurricane Katrina and, except for the partial restoration of oil production in mid September, remained shut-in for the remainder of the third quarter of 2005. Production was gradually restored in the fourth quarter of 2005 and the first quarter of 2006. As of March 31, 2006, we had restored approximately 90% of our total pre-hurricane volumes in South Louisiana, including the Burrwood/West Delta 83 field and the Second Bayou field, which was impacted to a lesser extent by Hurricane Rita in September 2005. Our remaining pre-hurricane production volumes are temporarily shut-in awaiting completion of facility and well repairs. Damage to our facilities from both hurricanes was substantially covered by insurance.

St. Gabriel Field — In the first quarter of 2006, we commenced an exploratory test well on our Bordeaux Prospect. In March 2006, we announced that an open hole log on the test well, the Gueymard No. 1, had encountered approximately 60 feet of net pay. The well was completed in April 2006 and has preliminarily tested at a gross production rate of approximately 4,000 Mcf of gas per day and 200 barrels of oil per day with 5,000 pounds of flowing tubing pressure. We currently anticipate drilling one additional well in the field later in 2006.

Accounting Pronouncements

See Note B to our Consolidated Financial Statements for a discussion of recently issued accounting pronouncements.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based on consolidated financial statements which have been prepared in accordance with generally accepted accounting principles in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts or assets, liabilities, revenues and expenses. We believe that certain accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements. Our 2005 Annual Report on Form 10-K, as amended, includes a discussion of our critical accounting policies. In addition, following the adoption of SFAS 123R, we consider our policies related to share-based compensation to be a critical accounting policy.

Share-Based Compensation Plans. In January 2006, we adopted SFAS 123R which amends SFAS 123 and supercedes APB 25. SFAS 123R requires new, modified and unvested share-based payment transactions with employees to be measured at fair value and recognized as compensation expense over the vesting period. The fair value of each option award is estimated using a Black-Scholes option valuation model that requires us to develop estimates for assumptions used in the model. The Black-Scholes valuation model uses the following assumptions: expected volatility, expected term of option, risk-free interest rate and dividend yield. Expected volatility estimates are developed by us based on historical volatility of our stock. We use historical data to estimate the expected term of the options. The risk-free interest rate for periods within the expected life of the option is based on the U.S. Treasury yield in effect at the grant date. Our common stock does not pay dividends; therefore the dividend yield is zero.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

We enter into futures contracts or other hedging agreements from time to time to manage the commodity price risk for a portion of our production. We consider these agreements to be hedging activities and, as such, monthly settlements on the contracts that qualify for hedge accounting are reflected in our crude oil and natural gas sales. Our strategy, which is administered by the Hedging Committee of the Board of Directors, and reviewed periodically by the entire Board of Directors, has been to generally hedge between 30% and 70% of our production. As of March 31, 2006, the commodity hedges we utilized were in the form of: (a) swaps, where we receive a fixed price and pay a floating price, based on NYMEX quoted prices; and (b) collars, where we receive the excess, if any, of the floor price over the reference price, based on NYMEX quoted prices, and pay the excess, if any, of the reference price over the ceiling price. See Note H to the Consolidated Financial Statements for additional information.

The fair value of the crude oil and natural gas hedging contracts in place at March 31, 2006 resulted in a liability of $14.7 million. Based on oil and gas pricing in effect at March 31, 2006, a hypothetical 10% increase in oil and gas prices would have increased the derivative liability to $21.6 million while a hypothetical 10% decrease in oil and gas prices would have decreased the derivative liability to an asset of $7.9 million.

Interest Rate Risk


Effective Date	Maturity Date	LIBOR Swap Rate		Notional Amount
02/27/06	02/26/07	4.08	%	$	23.0
02/27/06	02/26/07	4.85	%		17.0
02/26/07	02/26/09	4.86	%		40.0

The fair value of the interest rate swap contracts in place at March 31, 2006 resulted in an asset of $0.5 million. Based on interest rates at March 31, 2006, a hypothetical 10% increase or decrease in interest rates would not have a material effect on the asset.

Item 4. Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer performed an evaluation of our disclosure controls and procedures. As defined in Exchange Act Rules 13a-15(e) and 15d-15(e) under the Exchange Act, disclosure controls and procedures are controls and other procedures of the Company that are designed to ensure that information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Based on this evaluation, and following discussions with our independent registered public accounting firm, KPMG LLP, our Chief Executive Officer and Chief Financial Officer concluded that, as of March 31, 2006, due to the material weakness discussed in the subsequent paragraph, our disclosure controls and procedures were not effective as further detailed below.

On April 28, 2006, we were advised by our independent registered public accounting firm, KPMG LLP, of the discovery of an error in the failure to record the fair value of commodity price collars in place at March 31, 2006, which did not qualify for hedge accounting. We have corrected this error, which resulted in recording an additional charge to earnings of $1.9 million before taxes in the first quarter of 2006. No results of operations for prior periods were affected by this error.

We believe that our control procedures over recording the fair value of all outstanding derivatives were not operating effectively at March 31, 2006 and that this deficiency in internal control over financial reporting at March 31, 2006 is a material weakness. This control deficiency could result in a misstatement to our annual or interim financial statements that would not be prevented or detected. Our executive management is currently evaluating our accounting resource needs and existing controls over derivative accounting and anticipates taking appropriate remedial action in the near term.

Except as noted above, there has been no change in our internal controls over financial reporting that occurred during the three months ended March 31, 2006 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting. See Item 1A – “Risk Factors” in Part II of this Report.

PART II. OTHER INFORMATION

Item 1A – Risk Factors

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2005, which could materially affect our business, financial condition or future results. In addition, as disclosed in Part I, Item 4, we believe that our control procedures over recording the fair value of all outstanding derivatives were not operating effectively at March 31, 2006 and that this deficiency in internal control over financial reporting at March 31, 2006 is a material weakness. This control deficiency could result in a misstatement to our annual or interim financial statements that would not be prevented or detected. Please read Part I, Item 4 for more information about this control deficiency. The risks described in our Annual Report on Form 10-K and the risk associated with our identified deficiency in internal control over financial reporting, are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

Item 6 – Exhibits

(b)

Exhibits



*31.1		Certification of Chief Executive Officer Pursuant to 15 U.S.C Section 7241, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31.2		Certification of Chief Financial Officer Pursuant to 15 U.S.C. Section 7241, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

**32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

**32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*	Filed herewith

**	Furnished herewith

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned and thereunto duly authorized.


	GOODRICH PETROLEUM CORPORATION

Date: May 8, 2006	By:	/s/ Walter G. Goodrich
		Walter G. Goodrich Vice Chairman & Chief Executive Officer

Date: May 8, 2006	By:	/s/ D. Hughes Watler, Jr.
		D. Hughes Watler, Jr. Senior Vice President & Chief Financial Officer

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